Embodiments relate to well bore treatments and, more particularly, in certain embodiments, use of polymeric particulates that are temperature activated to mitigate problems with annular pressure buildup in subterranean wells.
Spacer fluids are often used in subterranean operations to facilitate improved displacement efficiency when introducing new fluids into a well bore. For example, a spacer fluid can be used to displace a fluid in a well bore before introduction of another fluid. When used for drilling fluid displacement, spacer fluids can enhance solids removal as well as separate the drilling fluid from a physically incompatible fluid. For instance, in well cementing operations, the spacer fluid may be placed into the well bore to separate the cement composition from the drilling fluid. If the spacer fluid does not adequately displace the drilling fluid, the cement composition may fail to bond to the pipe string and/or the formation to the desired extent. Spacer fluids also may be placed between different drilling fluids during drilling change outs or between a drilling fluid and a completion brine, for example.
Cement compositions may be used in a variety of subterranean applications. For example, in subterranean well construction, a pipe string (e.g., casing, liners, expandable tubulars, etc.) may be run into a well bore and cemented in place. The process of cementing the pipe string in place is commonly referred to as “primary cementing.” In a typical primary cementing method, a cement composition may be pumped into an annulus between the walls of the well bore and the exterior surface of the pipe string disposed therein. The cement composition may set in the well bore annulus, thereby forming an annular sheath of hardened, substantially impermeable cement (i.e., a cement sheath) that may support and position the pipe string in the well bore and may bond the exterior surface of the pipe string to the subterranean formation. Among other things, the cement sheath surrounding the pipe string functions to prevent the migration of fluids in the annulus, as well as protecting the pipe string from corrosion.
Hydrocarbon production from the subterranean well may be initiated at some point in time after the cementing operation is complete. For example, hydrocarbons may be produced at the surface after flowing into the well bore and up through the pipe string. These hydrocarbons (e.g., oil, gas, etc.) may be at elevated temperatures as they flow through up through the casing/tubing, thus transferring heat through the pipe string into the well bore annulus. This may cause fluids in the well bore annulus to expand. For example, spacer fluids remaining in the well bore annulus above the cement sheath may heat and expand. Such an expansion may cause an increase in pressure within the well bore annulus, which is commonly referred to as “annular pressure buildup.” Annular pressure buildup typically occurs when the annular volume is fixed. For instance, the well bore annulus may be closed (e.g., trapped) to isolate fluids in the well bore annulus from outside the annulus. Closing the well bore annulus typically occurs near the end of the cementing operation after well completion fluids such as spacer fluids and cement compositions are in place. By way of example, the well bore annulus may be closed by closing a valve, energizing a seal, and the like. However, if a fluid is trapped in the closed well bore annulus experiences a temperature increase, a large pressure increase may be expected because the volume in the well bore annulus is fixed. In some instances, this pressure increase may cause damage to the well bore, such as damage to the cement sheath, casing, tubulars, or other equipment in the well bore.
A number of different techniques have been used to combat annular pressure buildup, including use of a syntactic foam wrapping on the casing, placing nitrified spacer fluids above the cement in the annulus, placing rupture disks in an outer casing string, designing “shortfalls” in the primary cementing operations such as designing the top of the cement column in an annulus to be short of the previous casing shoe, using hollow spheres, and others. However, such methods have drawbacks. For instance, the syntactic foam may cause flow restrictions during primary cementing of the casing within the wellbore. In addition, the syntactic foam may detach from the casing and/or become damaged as the casing is installed. Drawbacks with placing the nitrified spacer fluids include logistical difficulties (e.g., limited room for the accompanying surface equipment), pressure limitations on the well bore, and the typical high expenses related thereto. Further drawbacks with placing the nitrified spacer fluids include loss of returns when circulating the nitrified spacer into place and in situations wherein the geographic conditions provide difficulties in supplying the proper equipment for pumping the nitrified spacer. Additional drawbacks include the rupture disks so comprising the casing string after failure of the disks that continuing well bore operations may not be able to proceed. Further drawbacks include the designed “shortfall,” which may not occur due to well bore fluids not being displaced as designed and cement channeling up to a casing shoe and trapping it. Moreover, problems with the hollow spheres include the spheres failing before placement in the annulus and inability to withstand repeated changes in pressure/temperature.